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Utility Rate Regulation - Regulatory Liabilities (Details) - USD ($) $ in Millions | 6 Months Ended |
--- | --- | ---
Jun. 30, 2023 | Dec. 31, 2022
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | $ 280 | $ 238
Noncurrent regulatory liabilities | $ 3,421 | 3,412
Utility Rate Regulation | 6. Utility Rate Regulation (All Registrants) The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations.
| PPL |  | PPL Electric |  | LG&E |  | KU
| June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022
Current Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas supply clause | $ | — |  |  | $ | 41 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 13 |  |  | $ | — |  |  | $ | — |
Rate adjustment mechanisms | 214 |  |  | 96 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Renewable energy certificates | 13 |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Derivative instruments | 15 |  | 41 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Smart meter rider | 5 |  |  | 5 |  |  | 5 |  |  | 5 |  |  | — |  |  | — |  |  | — |  |  | — |
Universal service rider | 21 |  |  | 3 |  |  | 21 |  |  | 3 |  |  | — |  |  | — |  |  | — |  |  | — |
Fuel adjustment clause | 9 |  |  | 38 |  |  | — |  |  | — |  |  | 2 |  |  | 9 |  |  | 7 |  |  | 29 |
Transmission service charge | 12 |  |  | — |  |  | 12 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 42 |  |  | 20 |  |  | 11 |  |  | 5 |  |  | 2 |  |  | 1 |  |  | 3 |  |  | 3 |
Total current regulatory assets | $ | 331 |  |  | $ | 258 |  |  | $ | 49 |  |  | $ | 13 |  |  | $ | 4 |  |  | $ | 23 |  |  | $ | 10 |  |  | $ | 32 |
Noncurrent Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Defined benefit plans | $ | 783 |  |  | $ | 778 |  |  | $ | 353 |  |  | $ | 353 |  |  | $ | 208 |  |  | $ | 209 |  |  | $ | 139 |  |  | $ | 140 |
Plant outage costs | 42 |  |  | 46 |  |  | — |  |  | — |  |  | 11 |  |  | 12 |  |  | 31 |  |  | 34 |
Net metering | 89 |  |  | 61 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Environmental cost recovery | 101 |  |  | 102 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Taxes recoverable through future rates | 38 |  |  | 47 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm costs | 111 |  |  | 118 |  |  | — |  |  | — |  |  | 15 |  |  | 7 |  |  | 14 |  |  | 3 |
Unamortized loss on debt | 24 |  |  | 21 |  |  | 4 |  |  | 3 |  |  | 11 |  |  | 11 |  |  | 7 |  |  | 7 |
Interest rate swaps | 6 |  |  | 7 |  |  | — |  |  | — |  |  | 6 |  |  | 7 |  |  | — |  |  | — |
Terminated interest rate swaps | 61 |  |  | 63 |  |  | — |  |  | — |  |  | 36 |  |  | 37 |  |  | 25 |  |  | 26 |
Accumulated cost of removal of utility plant | 195 |  |  | 212 |  |  | 195 |  |  | 212 |  |  | — |  |  | — |  |  | — |  |  | — |
AROs | 292 |  |  | 295 |  |  | — |  |  | — |  |  | 76 |  |  | 76 |  |  | 216 |  |  | 219 |
Derivatives instruments | 7 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 77 |  |  | 69 |  |  | — |  |  | — |  |  | 21 |  |  | 14 |  |  | 15 |  |  | 13 |
Total noncurrent regulatory assets | $ | 1,826 |  |  | $ | 1,819 |  |  | $ | 552 |  |  | $ | 568 |  |  | $ | 384 |  |  | $ | 373 |  |  | $ | 447 |  |  | $ | 442 |
| PPL |  | PPL Electric |  | LG&E |  | KU
| June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022
Current Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Generation supply charge | $ | 41 |  |  | $ | 37 |  |  | $ | 41 |  |  | $ | 37 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Transmission service charge | — |  |  | 14 |  |  | — |  |  | 7 |  |  | — |  |  | — |  |  | — |  |  | — |
TCJA customer refund | 6 |  |  | 15 |  |  | 6 |  |  | 15 |  |  | — |  |  | — |  |  | — |  |  | — |
Act 129 compliance rider | 15 |  |  | 14 |  |  | 15 |  |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |
Transmission formula rate | 23 |  |  | 12 |  |  | 20 |  |  | 12 |  |  | — |  |  | — |  |  | — |  |  | — |
Rate adjustment mechanism | 133 |  |  | 96 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Energy efficiency | 23 |  |  | 23 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Gas supply clause | 16 |  |  | — |  |  | — |  |  | — |  |  | 16 |  |  | — |  |  | — |  |  | — |
Other | 23 |  |  | 27 |  |  | — |  |  | — |  |  | 3 |  |  | 7 |  |  | 2 |  |  | 6 |
Total current regulatory liabilities | $ | 280 |  |  | $ | 238 |  |  | $ | 82 |  |  | $ | 85 |  |  | $ | 19 |  |  | $ | 7 |  |  | $ | 2 |  |  | $ | 6 |
| PPL |  | PPL Electric |  | LG&E |  | KU
| June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022 |  | June 30, 2023 |  | December 31, 2022
Noncurrent Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accumulated cost of removal of utility plant | $ | 978 |  |  | $ | 950 |  |  | $ | — |  |  | $ | — |  |  | $ | 296 |  |  | $ | 287 |  |  | $ | 396 |  |  | $ | 389 |
Power purchase agreement - OVEC | 22 |  |  | 26 |  |  | — |  |  | — |  |  | 15 |  |  | 18 |  |  | 7 |  |  | 8 |
Net deferred taxes | 2,054 |  |  | 2,094 |  |  | 776 |  |  | 775 |  |  | 469 |  |  | 477 |  |  | 535 |  |  | 546 |
Defined benefit plans | 225 |  |  | 187 |  |  | 59 |  |  | 45 |  |  | 21 |  |  | 21 |  |  | 57 |  |  | 56 |
Terminated interest rate swaps | 58 |  |  | 60 |  |  | — |  |  | — |  |  | 29 |  |  | 30 |  |  | 29 |  |  | 30 |
Energy efficiency | 39 |  |  | 32 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 45 |  |  | 63 |  |  | — |  |  | — |  |  | 3 |  |  | — |  |  | 8 |  |  | — |
Total noncurrent regulatory liabilities | $ | 3,421 |  |  | $ | 3,412 |  |  | $ | 835 |  |  | $ | 820 |  |  | $ | 833 |  |  | $ | 833 |  |  | $ | 1,032 |  |  | $ | 1,029 |
Regulatory Matters Rhode Island Activities (PPL) Rate Case proceedings Pursuant to Report and Order No. 23823 issued May 5, 2020, the RIPUC approved the terms of an Amended Settlement Agreement (ASA), reflecting an allowed return on equity (ROE) rate of 9.275% based on a common equity ratio of approximately 51%. RIE is currently in year five of the multi-year rate plan (Rate Plan). On June 30, 2021, the Rhode Island Division of Public Utilities and Carriers consented to an open-ended extension of the term of the Rate Plan. Pursuant to the settlement with the Rhode Island Office of the Attorney General in connection with the acquisition of RIE by PPL, RIE currently does not anticipate filing a new base rate case before May 25, 2025. Pursuant to the open-ended extension, the Rate Year 3 level of base distribution rates under ASA will remain in effect and RIE will continue to operate under the current Rate Plan until a new Rate Plan is approved by the RIPUC. The ASA includes additional provisions, including (i) an Electric Transportation Initiative (the ET Initiative) to facilitate the growth of Electric Vehicle (EV) adoption and scaling of the market for EV charging equipment to advance Rhode Island's zero emission vehicles and greenhouse gas emissions policy goals, (ii) two energy storage demonstration projects, which are on track for timely completion, (iii) an incentive-only performance incentive for System Efficiency: Annual Megawatt Capacity Savings, which sunset in 2021 and is now a tracking and reporting only metric, and (iv) several additional metrics for tracking and reporting purposes only. The RIPUC discussed the ET Initiative at an Open Meeting on August 30, 2022, advising RIE to seek RIPUC authorization to continue the ET Initiative and/or to alter any of the targets established in the ASA for Rate Year 5 and beyond. No votes or official rulings were taken; however, based on this feedback, RIE has paused the ET programs in Rate Year 5. As of June 30, 2023, the RIPUC had not made any rulings regarding the timing of crediting customers the deferral balance pursuant to the ASA. RIE cannot predict the outcome of this matter. Advanced Metering Functionality and Grid Modernization In 2021, RIE filed its Updated Advanced Metering Functionality (AMF) Business Case and Grid Modernization Plan (GMP) with the RIPUC in accordance with the ASA, and which, among other things, sought approval to deploy smart meters throughout the service territory. In 2021, the RIPUC stayed the AMF and GMP proceedings pending further consideration following the issuance of a final Order by the Rhode Island Division of Public Utilities and Carriers on the acquisition of RIE. RIE filed notice of withdrawal of the original Updated AMF Business Case and GMP with the RIPUC, and in November 2022 filed a new AMF Business Case with the RIPUC. The new AMF Business Case filing consists of a detailed proposal for full-scale deployment of AMF across its electric service territory. The proposal will enable significant customer and grid benefits in line with the state’s climate mandates. In its filing, RIE estimated that the proposed program would cost $188 million on a net present value (NPV) basis and provide benefits of $729 million NPV over the 20-year project life, yielding a benefit-cost ratio of 3.9%. RIE believes AMF is a foundational technology that is a necessary first step to transforming Rhode Island’s electric distribution system. In its filing, RIE requested a RIPUC decision by June 2023; the RIPUC issued a revised procedural schedule for the AMF Business Case filing that provides for hearings in July 2023. Evidentiary hearings commenced on July 20, 2023 and continued on July 25, 2023 through July 27, 2023. In addition, the RIPUC held a public comment hearing on April 4, 2023, and technical sessions on February 22, 2023, May 10, 2023 and June 13, 2023. The RIPUC also held a separate evidentiary hearing on April 14, 2023, regarding certain Motions for Confidential Treatment by RIE. RIE filed a new GMP with the RIPUC on December 30, 2022. The new GMP filing consists of a holistic suite of grid modernization investments that will provide RIE with the tools and capability to manage the electric distribution system more granularly considering a range of distributed energy resources adoption levels, accelerated by Rhode Island's climate mandates, while at the same time maintaining a safe and reliable electric distribution system. The GMP is an informational guidance document that supports the grid modernization investments to be proposed in future electric ISR plans. Consequently, RIE did not request approval from the RIPUC for any specific investments or seek cost recovery as part of the GMP; rather, RIE requested that the RIPUC issue an order affirming RIE’s compliance with its obligation to file a GMP that meets the requirements of the ASA. COVID-19 Deferral Filing On April 30, 2021, RIE filed a petition for approval to recognize regulatory assets related to COVID-19 impacts (RIPUC Docket No. 5154). In its petition, RIE sought the RIPUC's authorization to create regulatory assets and consideration of future cost recovery for the following COVID-19 costs: (1) the increased cost of customer accounts receivable that RIE will be unable to collect as a result of the COVID-19 pandemic, and the executive orders and RIPUC orders restricting RIE's collection activities as a result of the pandemic, which will result in increased net charge-offs; (2) lost revenue from unassessed late payment charges; and (3) charges to RIE for other fees that RIE has waived pursuant to the RIPUC's orders in RIPUC Docket No. 5022. RIE is evaluating its request to create a regulatory asset for COVID-19-related bad debt expense to consider the impact, if any, of the proposed arrearage forgiveness sought in RIE’s Petition to Forgive Certain Arrearage Balances for Low-Income and Protected Customers in Docket No. 22-08-GE, which RIE filed with the RIPUC to fulfill its obligations under PPL's settlement with the Rhode Island Attorney General. RIE cannot predict the outcome of this matter. FY 2023 Gas Infrastructure, Safety and Reliability (ISR) Plan At an Open Meeting on March 29, 2022, the RIPUC conditionally approved RIE’s FY 2023 Gas ISR Plan and associated revenue requirement, subject to further review regarding RIE's Proactive Main Replacement Program and its decision to reconstruct and purchase heating and pressure regulation equipment located at RIE’s Wampanoag and Tiverton take stations. The RIPUC held an Open Meeting on September 13, 2022, and issued its Order on November 18, 2022 regarding the Proactive Main Replacement Program and made the following rulings: (1) commencing with the Gas ISR plan to be filed in this calendar year 2022 (prospectively), new main constructed to replace leak prone pipe will not be considered used and useful, and therefore not eligible for rate base treatment, until the related old main is abandoned; and (2) approved the proactive main replacement revenue requirement set forth in the FY2023 Gas ISR plan. Also, the RIPUC directed RIE to submit prefiled testimony on the issue of its replacement of heating and pressure regulation facilities at the Wampanoag and Tiverton take stations and to address three issues, specifically: (i) a cost-benefit analysis arising from RIE's decision to take ownership of the reconstructed take station equipment; (ii) the potential that the benefits derived from the reconstruction and ownership transfer of the take station equipment will not be realized due to the future use of hydrogen or abandonment of the gas system; and (iii) the depreciation and accounting treatment of the reconstructed take station equipment. RIE filed this testimony with the RIPUC on May 16, 2022, the RIPUC has not taken any action to date on this issue. RIE cannot predict the outcome of this matter. FY 2024 Gas ISR Plan On December 23, 2022, RIE filed its FY 2024 Gas ISR Plan with the RIPUC. At its January 20, 2023 Open Meeting, the RIPUC directed RIE to file supplemental budget and rate schedules to reflect an April 1 to March 31 fiscal year. The supplemental budget that was filed with the RIPUC on January 27, 2023 includes $187 million of capital investment spend. The supplemental rate schedules were filed on February 3, 2023. RIE and the Rhode Island Division of Public Utilities and Carrier s reached an agreement on an approximately $171 million capital investment spending plan, and RIE filed a second supplemental budget on March 13, 2023. The RIPUC held a hearing on the plan on March 14, 2023. At an Open Meeting on March 29, 2023, the RIPUC approved the plan with an adjustment to the budget for the Proactive Main Replacement Program category resulting in a total approved FY 2024 Gas ISR Plan of $163 million for capital investment spend. On March 31, 2023, the RIPUC approved RIE's March 30, 2023 compliance filing for rates effective April 1, 2023. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan process. RIE cannot predict the outcome of this matter. FY 2024 Electric ISR Plan On December 23, 2022, RIE filed its FY 2024 Electric ISR Plan with the RIPUC. At its January 20, 2023 Open Meeting, the RIPUC directed RIE to file supplemental budget and rate schedules to reflect an April 1 to March 31 fiscal year. The supplemental budget filed with the RIPUC on January 27, 2023 includes $176 million of capital investment spend, $14 million of vegetation operations and management (O&M) spend and $3 million of Other O&M spend. The supplemental rate schedules were filed on February 3, 2023. RIE filed second supplemental budget schedules on March 21, 2023, which includes $166 million of capital investment spend, $14 million of vegetation management O&M spend and $1 million of Other O&M spend. The RIPUC held hearings in March 2023, and on March 29, 2023, approved the plan with modifications to the proposed capital investment spend, resulting in a total approved FY 2024 Electric ISR Plan of $112 million for capital investment spend, $14 million for vegetation management O&M spend, and $1 million for Other O&M spend. On March 31, 2023, the RIPUC approved RIE's March 30, 2023 compliance filing for rates effective April 1, 2023. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan process. RIE cannot predict the outcome of this matter. Kentucky Activities (PPL, LG&E and KU) CPCN and SB 4 Application On December 15, 2022, LG&E and KU filed an application with the KPSC for a CPCN for the construction of two 621 MW net summer rating NGCC combustion turbine facilities, one at LG&E's Mill Creek Generating Station in Jefferson County, Kentucky and the other at KU's E.W. Brown Generating Station in Mercer County, Kentucky, including on-site natural gas and electric transmission construction associated with those facilities and site compatibility certificates. LG&E and KU also applied for a CPCN to construct a 120 MWac solar photovoltaic electric generating facility in Mercer County, Kentucky, and for a CPCN to acquire a 120 MWac solar facility to be built by a third-party solar developer in Marion County, Kentucky. LG&E and KU further applied for a CPCN to construct a 125 MW, 4-hour battery energy storage system facility at KU's E.W. Brown Generating Station and for approval of their proposed 2024-2030 DSM programs. The plan includes adding 14 new, adjusted or expanded energy efficiency programs, which would reduce LG&E's and KU's overall need by approximately 100 MW each. Finally, LG&E and KU requested a declaratory order to confirm that their entry into non-firm energy-only power-purchase agreements for the output of four solar photovoltaic facilities with a combined capacity of 637 MW does not require KPSC approval and that LG&E and KU may recover the costs of the solar PPAs through their fuel adjustment clause mechanisms as previously approved for a prior solar PPA. LG&E and KU plan to accrue AFUDC on the constructed NGCC facilities, the solar facility in Mercer County, Kentucky and the battery energy storage system facility and have requested regulatory asset treatment to recover the financing costs of these projects. The new NGCC facilities would be jointly owned by LG&E (31%) and KU (69%) and the solar units would be jointly owned by LG&E (37%) and KU (63%), the battery storage unit would be owned by LG&E, and the proposed PPA transactions and DSM programs would be entered into or conducted jointly by LG&E and KU, consistent with LG&E and KU's shared dispatch, cost allocation, tariff or other frameworks. The filing also notes planned retirement dates for certain existing coal-fired generation units, including Mill Creek 1 (300 MW) in 2024 and E.W. Brown 3 (412 MW) in 2028, and updates and advances the planned retirement dates for Mill Creek 2 (297 MW) to 2027 and Ghent 2 (486 MW) to 2028. LG&E and KU anticipate the recovery of associated retirement costs, including the remaining net book value, for these coal-fired generating units through the RAR or other rate mechanisms. The KPSC accepted the CPCN filing as of January 6, 2023. On March 24, 2023, Kentucky Senate Bill 4 (SB 4) went into effect, which requires KPSC approval of fossil fuel-fired electric generating unit retirements in the state. On May 10, 2023, LG&E and KU filed an application with the KPSC seeking approval of the retirement of seven fossil fuel-fired generating units as required by the recently enacted SB 4. On May 16, 2023, the KPSC entered an Order consolidating the SB 4 filing proceeding into the CPCN case. The KPSC has indicated its intention to issue an order on all issues by November 6, 2023. PPL, LG&E and KU cannot predict the outcome of these matters. Kentucky March 2023 Storm On March 3, 2023, LG&E and KU experienced significant windstorm activity in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets with total costs incurred through June 30, 2023 of $75 million ($33 million at LG&E and $42 million at KU). On March 17, 2023, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance expenses portion of the costs incurred related to the windstorm. On April 5, 2023, the KPSC issued an order approving the request for accounting purposes, noting that approval for recovery would be determined in LG&E’s and KU’s next base rate cases. As of June 30, 2023, LG&E and KU recorded regulatory assets related to the storm of $8 million and $11 million. Pennsylvania Activities (PPL and PPL Electric) PAPUC investigation into billing issues On January 31, 2023, the PAPUC initiated an investigation focused on billing issues related to estimated, irregular bills and customer service concerns following customer complaints, which for many customers were driven by increased prices for electricity supply. Certain bills issued during the time period of December 20, 2022 through January 25, 2023 were estimated due to a technical issue that prevented PPL Electric from providing actual collected meter data to customer facing and other internal systems. Customers also reported difficulties accessing PPL Electric's website and contacting the customer service call center. The PAPUC’s Bureau of Investigation & Enforcement has directed PPL Electric to respond to certain inquiries and document requests. PPL Electric has submitted its responses to the information request and is cooperating fully with the investigation. PPL Electric cannot predict the outcome of this matter. Federal Matters FERC Transmission Rate Filing (PPL, LG&E and KU) In 2018, LG&E and KU applied to the FERC requesting elimination of certain on-going waivers and credits to a sub-set of transmission customers relating to the 1998 merger of LG&E's and KU's parent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a regional transmission operator and energy market. The application sought termination of LG&E's and KU's commitment to provide certain Kentucky municipalities mitigation for certain horizontal market power concerns arising out of the 1998 LG&E and KU merger and 2006 MISO withdrawal. The amounts at issue are generally waivers or credits granted to a limited number of Kentucky municipalities for either certain LG&E and KU or MISO transmission charges incurred for transmission service received. In 2019, the FERC granted LG&E's and KU's request to remove the ongoing credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, which was subsequently filed, modified, and approved by the FERC in 2020 and 2021. In 2020, LG&E and KU and other parties filed appeals with the D.C. Circuit Court of Appeals regarding the FERC's orders on the elimination of the mitigation and required transition mechanism. In August 2022, the D.C. Circuit Court of Appeals issued an order remanding the proceedings back to the FERC. On May 18, 2023, the FERC issued an order on remand reversing its 2019 decision and requiring LG&E and KU to refund credits previously withheld, including under such transition mechanism. On June 9, 2023, the FERC granted LG&E’s and KU’s motion for an extension of time to process refunds until November 2023. LG&E and KU filed a request for rehearing of the May 18, 2023 order, which was denied by operation of law on July 17, 2023. LG&E and KU filed petition for review of FERC's May 18, 2023 order with the D.C. Circuit Court of Appeals on July 28, 2023. In the second quarter of 2023, LG&E and KU recorded regulatory liabilities of $3 million and $8 million related to potential refunds resulting from the FERC’s May 18, 2023 order. LG&E and KU cannot predict the ultimate outcome of the proceedings or any other post decision process but do not expect the annual impact to have a material effect on their operations or financial condition. LG&E and KU currently receive recovery of certain waivers and credits provided primarily through base rates with increases associated with the FERC's May 18, 2023 order expected to be primarily subject to base rate recovery in future rate proceedings. Recovery of Transmission Costs (PPL) Until December 2022, RIE's transmission facilities were operated in combination with the transmission facilities of National Grid's New England affiliates, Massachusetts Electric Company (MECO) and New England Power (NEP), as a single integrated system with NEP designated as the combined operator. As of January 1, 2023, RIE operates its own transmission facilities. NE-ISO allocates RIE's costs among transmission customers in New England, in accordance with the ISO Open Access Transmission Tariff (ISO-NE OATT). According to the FERC orders, RIE is compensated for its actual monthly transmission costs, with its authorized maximum ROE of 11.74% on its transmission assets. The ROE for transmission rates under the ISO-NE OATT is the subject of four complaints that are pending before the FERC. On October 16, 2014, the FERC issued an order on the first complaint, Opinion No. 531-A, resetting the base ROE applicable to transmission assets under the ISO-NE OATT from 11.14% to 10.57% effective as of October 16, 2014 and establishing a maximum ROE of 11.74%. On April 14, 2017, this order was vacated and remanded by the D. C. Circuit Court of Appeals (Court of Appeals). After the remand, the FERC issued an order on October 16, 2018 applicable to all four pending cases where it proposed a new base ROE methodology that, with subsequent input and support from the New England Transmission Owners (NETO), yielded a base ROE of 10.41%. Subsequent to the FERC's October 2018 order in the New England Transmission Owners cases, the FERC further refined its ROE methodology in another proceeding and has applied that refined methodology to transmission owners’ ROEs in other jurisdictions, and the NETOs filed further information in the New England matters to distinguish their case. Those determinations in other jurisdictions are currently on appeal before the Court of Appeals. The proceeding and the final base rate ROE determination in the New England matters remain open, pending a final order from the FERC. PPL cannot predict the outcome of this matter, and an estimate of the impact cannot be determined. Other Purchase of Receivables Program (PPL and PPL Electric) In accordance with a PAPUC-approved purchase of accounts receivable program, PPL Electric purchases certain accounts receivable from alternative electricity suppliers at a discount, which reflects a provision for uncollectible accounts. The alternative electricity suppliers have no continuing involvement or interest in the purchased accounts receivable. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. During the three and six months ended June 30, 2023, PPL Electric purchased $374 million and $732 million of accounts receivable from alternative suppliers. During the three and six months ended June 30, 2022, PPL Electric purchased $273 million and $622 million of receivables. (PPL) In 2021 and 2022, the RIPUC approved various components of a Purchase of Receivables Program (POR) in Rhode Island for effect on April 1, 2022. Municipal aggregators and non-regulated power producers (collectively, Competitive Suppliers) are eligible to participate in accordance with RIE's approved electric tariffs for municipal aggregation and non-regulated power producers. Under the POR program, RIE will purchase the Competitive Suppliers' accounts receivables, including existing receivables, at discounted rates, regardless of whether RIE has collected the owed monies from customers. The program is intended to make RIE whole through the implementation of a discount rate or Standard Complete Bill Percentage (SCBP) paid by Competitive Suppliers. RIE calculates the SCBP for each customer class and files the calculations with the RIPUC for review and approval by February 15 of each year. At an Open Meeting on March 29, 2023, the RIPUC approved the SCBP for effect beginning on April 1, 2023, for a one-year period. |
Generation Supply Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | $ 41 | 37
TCJA customer refund [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 6 | 15
Act 129 Compliance Rider [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 15 | 14
Accumulated Cost Of Removal Of Utility Plant [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 978 | 950
Power Purchase Agreement OVEC [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 22 | 26
Net deferred taxes [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 2,054 | 2,094
Defined Benefit Plans [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 225 | 187
Terminated interest rate swaps [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 58 | 60
Other Regulatory Liabilities [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 23 | 27
Noncurrent regulatory liabilities | 45 | 63
Transmission Service Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 14
Energy efficiency charge |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 23 | 23
Noncurrent regulatory liabilities | 39 | 32
Rate adjustment mechanism |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 133 | 96
Transmission Formula Rate [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 23 | 12
Gas supply clause [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 16 | 0
PPL Electric Utilities Corp [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 82 | 85
Noncurrent regulatory liabilities | 835 | 820
PPL Electric Utilities Corp [Member] | Generation Supply Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 41 | 37
PPL Electric Utilities Corp [Member] | TCJA customer refund [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 6 | 15
PPL Electric Utilities Corp [Member] | Act 129 Compliance Rider [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 15 | 14
PPL Electric Utilities Corp [Member] | Accumulated Cost Of Removal Of Utility Plant [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 0 | 0
PPL Electric Utilities Corp [Member] | Power Purchase Agreement OVEC [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 0 | 0
PPL Electric Utilities Corp [Member] | Net deferred taxes [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 776 | 775
PPL Electric Utilities Corp [Member] | Defined Benefit Plans [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 59 | 45
PPL Electric Utilities Corp [Member] | Terminated interest rate swaps [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 0 | 0
PPL Electric Utilities Corp [Member] | Other Regulatory Liabilities [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Noncurrent regulatory liabilities | 0 | 0
PPL Electric Utilities Corp [Member] | Transmission Service Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 7
PPL Electric Utilities Corp [Member] | Energy efficiency charge |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Noncurrent regulatory liabilities | 0 | 0
PPL Electric Utilities Corp [Member] | Rate adjustment mechanism |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
PPL Electric Utilities Corp [Member] | Transmission Formula Rate [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 20 | 12
PPL Electric Utilities Corp [Member] | Gas supply clause [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 19 | 7
Noncurrent regulatory liabilities | 833 | 833
Louisville Gas And Electric Co [Member] | Generation Supply Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] | TCJA customer refund [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] | Act 129 Compliance Rider [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] | Accumulated Cost Of Removal Of Utility Plant [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 296 | 287
Louisville Gas And Electric Co [Member] | Power Purchase Agreement OVEC [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 15 | 18
Louisville Gas And Electric Co [Member] | Net deferred taxes [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 469 | 477
Louisville Gas And Electric Co [Member] | Defined Benefit Plans [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 21 | 21
Louisville Gas And Electric Co [Member] | Terminated interest rate swaps [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 29 | 30
Louisville Gas And Electric Co [Member] | Other Regulatory Liabilities [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 3 | 7
Noncurrent regulatory liabilities | 3 | 0
Louisville Gas And Electric Co [Member] | Transmission Service Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] | Energy efficiency charge |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Noncurrent regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] | Rate adjustment mechanism |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] | Transmission Formula Rate [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Louisville Gas And Electric Co [Member] | Gas supply clause [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 16 | 0
Kentucky Utilities Co [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 2 | 6
Noncurrent regulatory liabilities | 1,032 | 1,029
Kentucky Utilities Co [Member] | Generation Supply Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Kentucky Utilities Co [Member] | TCJA customer refund [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Kentucky Utilities Co [Member] | Act 129 Compliance Rider [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Kentucky Utilities Co [Member] | Accumulated Cost Of Removal Of Utility Plant [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 396 | 389
Kentucky Utilities Co [Member] | Power Purchase Agreement OVEC [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 7 | 8
Kentucky Utilities Co [Member] | Net deferred taxes [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 535 | 546
Kentucky Utilities Co [Member] | Defined Benefit Plans [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 57 | 56
Kentucky Utilities Co [Member] | Terminated interest rate swaps [Member] |  |
Regulatory Liabilities [Line Items] |  |
Noncurrent regulatory liabilities | 29 | 30
Kentucky Utilities Co [Member] | Other Regulatory Liabilities [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 2 | 6
Noncurrent regulatory liabilities | 8 | 0
Kentucky Utilities Co [Member] | Transmission Service Charge [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Kentucky Utilities Co [Member] | Energy efficiency charge |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Noncurrent regulatory liabilities | 0 | 0
Kentucky Utilities Co [Member] | Rate adjustment mechanism |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Kentucky Utilities Co [Member] | Transmission Formula Rate [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | 0 | 0
Kentucky Utilities Co [Member] | Gas supply clause [Member] |  |
Regulatory Liabilities [Line Items] |  |
Current regulatory liabilities | $ 0 | $ 0

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